In many formations, chemical and/or physical processes alter the reservoir rock over geologic time. Sometimes, these diagenetic processes restrict the openings in the rock and reduce the ability of fluids to flow through the rock. If fluids cannot flow, it will be difficult to produce oil, gas or water from a well. Thus, low permeability reservoirs are often fractured to increase their production of fluids.
Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking. During injection the resistance to flow in the formation increases, the pressure in the wellbore increases to a value called the break-down pressure, that is the sum of the in situ compressive stress and the strength of the formation. Once the formation “breaks down,” a fracture is formed, and then injected fluid can flow through it. From a limited group of active perforations, ideally a single, vertical fracture is created that propagates in two “wings” being 180° apart and identical in shape and size, but in practice may have a different shape and size because of local in-homogeneities. In naturally fractured or cleated formations, it is possible that multiple fractures are created and/or the two wings evolve in a tree-like pattern with increasing number of branches away from the injection point.
In general, hydraulic fracture treatments are used to increase the productivity index of a producing well or the injectivity index of an injection well. The productivity index defines the rate at which oil or gas can be produced at a given pressure differential between the reservoir and the wellbore, while the injectivity index refers to the rate at which fluid can be injected into a well at a given pressure differential.
Fluid not containing any solid (called the “pad”) is injected first, until the fracture is wide enough to accept a propping agent. The purpose of the propping agent is to keep apart the fracture surfaces once the pumping operation ceases. In deep reservoirs, man-made ceramic beads are used to hold open or “prop” the fracture (see e.g., FIG. 1). In shallow reservoirs, sand is normally used as the propping agent.
Acid fracking is another technique that is sometimes used for carbonate-rich plays. Although many formations in North America are sandstone and require the use of granular propping agents, acid fracturing is more commonly used in Europe and the Middle East, especially in Bahrain and Saudi Arabia. In general, acid fracturing is best applied in shallow, low-temperature carbonate reservoirs, the best candidates having a temperature less than 200° F. Low temperature reduces the reaction rate between the acid and the formation, which allows the acid to penetrate deeper into the fracture before becoming spent.
Cost is another consideration when selecting acid-fracturing candidates. In hot reservoirs, expensive chemicals are required to inhibit the acid-reaction rate with the steel tubular goods and to retard the reaction rate with the formation. Thus, in deep, hot reservoirs, the cost of an acid-fracturing treatment can easily exceed the costs of a proppant-fracture treatment, making such techniques uneconomic.
The most commonly used fluid in acid fracturing is 15% hydrochloric acid (HCl). To obtain more acid penetration and more etching 28% HCl is sometimes used as the primary acid fluid. On occasion, formic acid (HCOOH) or acetic acid (CH3COOH) is used because these acids are easier to inhibit under high-temperature conditions. However, acetic and formic acid cost more than HCl, discouraging their use.
The reactions of HCl by carbonate (1) and dolomite (2) are shown:2HCl+CaCO3→CaCl2+H2O+CO2  (1)4HCl+CaMg(CO3)2→CaCl2+MgCl2+2H2O+CO2  2)
Mullamah (1991) studied reaction rate and how it varies with temperature, pressure, concentration, gravity and injection rate. He made the following conclusions:
1. The reaction rate increases with temperature up to 200° F. At temperatures higher than 200° F. the reaction rate becomes insensitive to increases in temperature.
2. The reaction at high temperatures requires pressures high enough to maintain the released CO2 dissolved in the spent acid solution. A system pressure of 1000 psi is not sufficient.
3. The reaction rate decreases as the pressure increases even when the pressure is high enough to maintain the released CO2 in solution. This is due to the effect of CO2 bubbles at the surface form a barrier between the approaching HCl molecules and the solid surface. Also the bubbles change the hydrodynamics of the boundary layer from laminar to transition or turbulent flow conditions.
4. The reaction rate increases as the acid concentration is increased up to 15% HCl. At higher acid concentrations the reaction rate decreases as the acid concentration increases.
5. The reaction rate increases as the injection rate increases. This is because the boundary layer decreases, and thus more contact with fresh acid occurs. The thickness of the boundary layer is inversely proportional to the square root of the fluid velocity regardless of the flow system used for the reaction.
6. The reaction rate is highest when the acid is flowed in the direction of the gravitational force.
In acid fracking, typically a gelled water or crosslinked gel fluid is used as the pad fluid to fill the wellbore and break down the formation. The water-based pad is then pumped to create the desired fracture height, width, and length for the hydraulic fracture. Once the desired values of created fracture dimensions are achieved, the acid is then pumped into the well and travels down the fracture to etch the walls of the fracture to increase conductivity (see FIG. 2).
Because the acid is reactive with the formation, fluid loss is a primary consideration in the fluid design. Large amounts of fluid-loss additives are generally added to the acid fluid to minimize fluid leakoff. Fluid-loss can be extreme in high permeability and/or naturally fractured carbonate formations, thus making long etched fractures difficult to obtain.
The main difference between acid fracturing and proppant fracturing is the way fracture conductivity is created. In proppant fracturing, a propping agent is used to prop open the fracture after the treatment is completed. In acid fracturing, acid is used to “etch” channels in the rock that comprise the walls of the fracture. Thus, the mineral has to be partially soluble in acid so that channels can be etched in the fracture walls. As such, the application of acid fracturing is confined to carbonate-rich reservoirs and is not used to stimulate sandstone, shale, or coal-seam reservoirs. Nevertheless, long etched fractures are difficult to obtain, because of high leakoff and rapid acid reaction with the formation.
Cryogenic fracturing has also been proposed, wherein very cold or cryogenic liquids are used in the fracking process. Expired patent, U.S. Pat. No. 3,822,747 by Maguire, for example, discloses creating a network of fractures is formed by injecting liquefied gases, such as liquid nitrogen (LN2), into a wellbore. As the liquefied gas vaporizes in the closed borehole, the resulting increase in pressure forms an initial group of fractures in the formation proximate to the borehole.
U.S. Pat. No. 7,823,644, U.S. Pat. No. 7,516,784, U.S. Pat. No. 7,784,545, U.S. Pat. No. 7,416,022, U.S. Pat. No. 7,264,049, and U.S. Pat. No. 7,198,107, also by Maguire, relate to methods for in-situ production of oil and other hydrocarbons, wherein a network of fractures is formed by injecting LN2 into at least one substantially horizontally disposed fracturing borehole.
U.S. Pat. No. 7,500,517, U.S. Pat. No. 7,789,164 and U.S. Pat. No. 8,104,536 generally relate to a method for the production of kerogen and other hydrocarbons from a reservoir, such as shale oil reservoirs, by pressurizing the formation with liquid or supercritical CO2 or other dense phase gases, and depressurizing the well to further fracture the formation. In this method associated adiabatic expansion of the CO2 cools the subsurface shale formation and causes thermal and mechanical stresses within the formation, which in turn leads to fracturing of the formation.
CA2777449 teaches LN2 use as a cryogenic fracking agent, and notes that it can be used together with an acid additive. However, that patent does not contemplate acid fracking therein, but only suggests low level acid use to scour tube perforations and clean up the near-wellbore area, or as corrosion inhibitors, scale inhibitors and iron controllers.
However, although many have performed test runs and research relating to cryogenic fracturing, the method has not been extensively employed in oil and gas production, and there remains further need to develop and optimize these methods for particular applications. This disclosure meets one or more of those needs.